System, Method, and Apparatus for Combined Fracturing Treatment and Scale Inhibition

ABSTRACT

A treatment fluid for a subterranean formation includes a carrier fluid and an amount of particles including a granular scale inhibitor. The carrier fluid includes a hydratable gel fluid, a crosslinked gel fluid, an acid-based fluid, an oil-based fluid, and/or a visco-elastic surfactant. The particles include a proppant impregnated with the scale inhibitor, a solid particle formed largely from the scale inhibitor, or both. The proppant includes scale inhibitor adsorbed on porous surfaces within the proppant, and/or a porous proppant with scale inhibitor embedded in the bulk porosity of the proppant. The scale inhibitor is present in an amount between about 1% and 5% of a total weight of particles. The particles include scale inhibitor at a sufficient concentration and dissolution rate to provide acceptable scale inhibitor concentrations in produced fluids for production volumes exceeding 500 pore volumes.

CROSS REFERENCE

The present application claims the benefit of U.S. Patent ProvisionalApplication No. 60/952,382, entitled “Fracture treatment fluid includinga granular scale inhibitor composition and method of use”, filed Jul.27, 2007, which is incorporated herein by reference in its entirety.

FIELD OF THE INVENTION

The present invention relates to inhibiting scale formation in wells,and more particularly but not exclusively relates to inhibiting scaleformation in hydraulically fractured fluid producing wells.

BACKGROUND

Scale formation in fluid-producing wells can reduce productivity of thewell or even stop production completely. Scale formation chemistry isgenerally understood, and conventional scale inhibition treatments areknown in the art. One conventional scale inhibition method consists ofinjecting a fluid including a scale inhibitor chemical into a formation,and flushing the chemical away from the wellbore with an amount offollow-up flushing fluid, where the chemical may be designed to adsorbto formation particle surfaces. The scale inhibitor chemical may beincluded in a water-based or oil-based fluid. One conventional scaletreatment involves coating particles with resin, and coating the resinwith scale inhibitor to prevent the resin coated particles from stickingtogether before treatment is completed, while the scale inhibitorcoating provides some scale inhibition after the treatment.Unfortunately, currently available scale inhibition treatments sufferfrom a few drawbacks. For example, currently available scale inhibitiontreatments do not inhibit scale for long periods of time and thereforerequire repeated application. In high flow areas of a well, for examplein an induced hydraulic fracture, the scale inhibitor is removed byproducing fluid quickly reducing the effectiveness of the treatment.Also, the available concentration of scale inhibitor declines rapidlyafter initial treatment, and therefore the scale inhibition proceduremust be repeated often or overdesigned with initial concentrations muchhigher than required to inhibit scale. Accordingly, there is a demandfor further improvements in this area of technology.

SUMMARY

One embodiment is a unique treatment fluid for inhibiting scaleformation in a producing well. Other embodiments include unique systemsand methods to control scale formation. Further embodiments, forms,objects, features, advantages, aspects, and benefits shall becomeapparent from the following description and drawings.

BRIEF DESCRIPTION OF THE FIGURES

FIG. 1 is a schematic diagram of a system for scale inhibition.

FIG. 2A is a schematic illustration of a particle.

FIG. 2B is a schematic illustration of a particle.

FIG. 3 is a schematic illustration of a coated particle.

FIG. 4 is an illustration of a fluid breaker profile.

FIG. 5 is an illustration of a scale inhibitor concentration versusproduction fluid flowback.

FIG. 6 is a schematic flow diagram of a procedure for scale inhibition.

DESCRIPTION OF THE ILLUSTRATIVE EMBODIMENTS

For the purposes of promoting an understanding of the principles of theinvention, reference will now be made to the embodiments illustrated inthe drawings and specific language will be used to describe the same. Itwill nevertheless be understood that no limitation of the scope of theinvention is thereby intended, and any alterations and furthermodifications in the illustrated embodiments, and any furtherapplications of the principles of the invention as illustrated thereinas would normally occur to one skilled in the art to which the inventionrelates are contemplated and protected.

FIG. 1 is a schematic diagram of a system 100 for scale inhibition. Thesystem 100 includes a wellbore 102 intersecting a subterranean formation104. The subterranean formation 104 may be a hydrocarbon bearingformation, or any other formation where fracturing may be utilized andinhibiting scale formation may be desirable. In certain embodiments, thesubterranean formation 104 may be for an injection well (such as forenhanced recovery or for storage or disposal) or in a production wellfor other fluids such as carbon dioxide or water. In certainembodiments, the system 100 includes an amount of treatment fluid 106.The treatment fluid 106 includes a carrier fluid 105, an amount ofparticles 107 where each particle defines a volume and includes a scaleinhibitor comprising at least a part of the defined volume. The definedvolume includes the particle, but does not include the surface of theparticle.

In certain embodiments, the amount of particles 107 include granularscale inhibitor particles 107 comprising at least partially, or evencompletely, solid scale inhibitor. In certain embodiments, the amount ofparticles 107 include proppant particles having a porosity—for exampleporous ceramic proppant particles—and having scale inhibitor storedwithin the porosity. In certain further embodiments, the scale inhibitorstored within the proppant porosity can be scale inhibitor adsorbed tointernal surfaces of the proppant, and/or scale inhibitor packed intothe bulk porosity of the proppant. In certain embodiments, the proppantmay be impregnated with the scale inhibitor. In certain furtherembodiments, the treatment fluid includes scale inhibitor as granularscale inhibitor particles and further includes scale inhibitor within aporous proppant particle.

The storage of scale inhibitor within the defined volume of solidparticles rather than within the liquid phase of the treatment fluidallows for a greater concentration of scale inhibitor and a configurabledispersion or dissolution time for the scale inhibitor. Further, thestorage of scale inhibitor within the defined volume of solid particlesallows for a greater concentration and a configurable dispersion ordissolution time for the scale inhibitor relative to a surface coatingof scale inhibitor, including dispersion times that can be much greaterthan the dispersion times of a surface coated scale inhibitor. Incertain embodiments, additional scale inhibitor may be included in theliquid phase of the treatment fluid and/or on the surface of or as acoating for the particles 107.

In certain embodiments, the solid granular scale inhibitors particlesinclude mixtures, blends, and/or filled polymers and the like and may bemanufactured in various solid shapes, including, but not limited tofibers, beads, films, ribbons and platelets. The scale inhibitor may becoated to promote adsorption to surfaces or to slow dissolution.Non-limiting examples of coatings include polycaprolate (a copolymer ofglycolide and epsilon-caprolactone), and calcium stearate, both of whichare hydrophobic. The term “coating” as used herein may refer toencapsulation or simply to changing the surface by chemical reaction orby forming or adding a thin film of another material. In certain furtherembodiments, the coating includes a material that degrades in contactwith a hydrocarbon, a material that degrades at a downhole temperature,and/or a material that degrades in a formation brine.

The appropriate combination of carrier fluid, scale inhibitor andproppant may be selected readily from available materials. The rate ofdissolution of the granular scale inhibitor is governed by factors suchas the choice of material, the ratio of materials, the particle size,calcining and coating of the solid material, the fluids and temperaturein the subterranean formation 104, and may readily and easily bedetermined by routine measurements. In certain embodiments, the scaleinhibitor comprises a particle size greater than about 25 microns (μm).In certain embodiments, the scale inhibitor is included on a proppant,and the proppant has a size at least equal to a 100-mesh proppant. Theembodiments provided are exemplary only, and various embodiments arecontemplated, with scale inhibitors included on particles smaller orlarger than those listed.

A scale inhibitor or inhibitors should be selected to be compatible withthe function of other components of the treatment fluid 106. Thegranular scale inhibitor and/or proppant including inhibitor may be partof a suspension in a treatment fluid in the wellbore, in theperforations, in a fracture 110, as a component of a filter cake on thewalls of a wellbore 102 or of a fracture 110, and/or in the pores of thesubterranean formation 104. In certain embodiments, the subterraneanformation 104 may be carbonate (including limestone and/or dolomite) orsandstone, although other formations benefitting from scale inhibitionare also contemplated.

In certain embodiments, the granular scale inhibitor is structured todegrade over time. The particle size of the granular scale inhibitor maybe almost any size transportable by the carrier fluid. Governing factorsfor size selection include at least a) the capability of equipment (e.g.a pump 108 and blender 112), b) the width of the fracture 110 generated,and c) the desired rate and time of particle degradation. The rate ofdegradation can readily be determined by routine measurements in alaboratory with a given fluid at a given temperature. In certainembodiments, the particles sizes of the granular scale inhibitor areselected to be similar to a proppant size and/or a fluid loss additivesize. In certain embodiments, the granular scale inhibitor includes thescale inhibitor and one or more other particulate materials.

In certain embodiments, additives are included as ordinarily used inoilfield treatment fluids 106. Additives should be checked forcompatibility with the scale inhibitor (in granular or within proppantform) and for interference with the performance of the scale inhibitor.If an additive includes a component (such as a buffer or a viscosifier)that may interact with the scale inhibitor, then either the amount ornature of the scale inhibitor, or the amount or nature of theinterfering or interfered-with component may be adjusted to compensatefor the interaction. Routine measurements and fluid tests in alaboratory may quantify additive-inhibitor interactions.

In certain embodiments, the scale inhibitor is included in an amountbetween about 1% and 5% by weight of a total amount of particles 107.For example, in a fracture treatment where the particles 107 include35,000 pounds of proppant with porosity or other features capable ofstoring scale inhibitor within the defined volume of the proppant, theamount of scale inhibitor in the proppant is between about 350 and 1,750pounds. In certain embodiments, the scale inhibitor may be included atlower than 1% or higher than 5%.

In certain embodiments, the system 100 further includes a pump 108 thatfractures the subterranean formation, and places the treatment fluid 106in the fracture 110. The pump 108 may receive treatment fluid 106 from ablender 112 that generates various fracture fluids including thetreatment fluid 106. In certain embodiments, the treatment fluid 106 isutilized at one or more stages of a fracturing treatment. For example,the fracture treatment may utilize a pad fluid comprising a viscosifiedfluid that has no particulates, followed by the treatment fluid 106including particulates, and concluding with a flush that has noparticulates. However, the treatment fluid 106 may be utilized in any orall stages of a fracture treatment.

In certain embodiments, the carrier fluid 105 may be stored in a tank114 and added to the treatment fluid 106 during operations. In certainembodiments, the carrier fluid 105 may be generated at the blender 112from a base fluid in the tank 114. The carrier fluid 105 includes anybase fluid known in the art that can be utilized to carry particulates,and the carrier fluid 105 typically includes a viscosifier. For example,the carrier fluid 105 may include a hydratable gel-based fluid, across-linked hydratable gel-based fluid, an oil-based fluid, avisco-elastic surfactant (VES) fluid, and an acid-based fluid.

The following exemplary viscosifiers are disclosed as illustrative only.Some nonlimiting examples of suitable polymers include guar gums,high-molecular weight polysaccharides composed of mannose and galactosesugars, or guar derivatives such as hydropropyl guar (HPG),carboxymethyl guar (CMG), and carboxymethylhydroxypropyl guar (CMHPG).Cellulose derivatives such as hydroxyethylcellulose (HEC) orhydroxypropylcellulose (HPC) and carboxymethylhydroxyethylcellulose(CMHEC) may also be used. Any useful polymer may be used in eithercrosslinked form, or without crosslinker in linear form. Xanthan,diutan, and scleroglucan have been shown to be useful as viscosifyingagents. Synthetic polymers such as polyacrylamide and polyacrylatepolymers and copolymers may be used in high-temperature applications. Incertain embodiments, the carrier fluid 105 includes a highlysalt-tolerant fluid, including a fluid that viscosifies in high salinityand that breaks in high salinity.

Nonlimiting examples of suitable viscoelastic surfactants (VES) includecationic surfactants, anionic surfactants, zwitterionic surfactants,amphoteric surfactants, nonionic surfactants, and combinations thereof.In certain embodiments, the VES fluid may include additionalfriction-reducing polymers. In certain embodiments, the carrier fluid105 includes a charged polymer in the presence of a surfactant having acharge that is opposite to that of the charged polymer, the surfactantbeing capable of forming an ion-pair association with the polymerresulting in a hydrophobically modified polymer having a plurality ofhydrophobic groups and enhanced viscosity, as described in publishedapplication U.S. 20040209780A1, Harris et. al.

In certain embodiments, the viscosifier is a water-dispersible, linear,nonionic, hydroxyalkyl galactomannan polymer or a substitutedhydroxyalkyl galactomannan polymer. Examples of useful hydroxyalkylgalactomannan polymers include, but are not limited to,hydroxy-C1-C4-alkyl galactomannans, such as hydroxy-C1-C4-alkyl guars.Preferred examples of such hydroxyalkyl guars include hydroxyethyl guar(HE guar), hydroxypropyl guar (HP guar), and hydroxybutyl guar (HBguar), and mixed C2-C4, C2/C3, C3/C4, or C2/C4 hydroxyalkyl guars.Hydroxymethyl groups can also be present in any of these.

When incorporated, the polymer based viscosifier may be present at anysuitable concentration. In various embodiments hereof, the gelling agentcan be present in an amount of from about 10 to less than about 60pounds per thousand gallons of liquid phase, or from about 15 to lessthan about 40 pounds per thousand gallons, from about 15 to about 35pounds per thousand gallons, 15 to about 25 pounds per thousand gallons,or even from about 17 to about 22 pounds per thousand gallons.Generally, the gelling agent can be present in an amount of from about10 to less than about 50 pounds per thousand gallons of liquid phase,with a lower limit of polymer being no less than about 10, 11, 12, 13,14, 15, 16, 17, 18, or 19 pounds per thousand gallons of the liquidphase, and the upper limited being less than about 50 pounds perthousand gallons, no greater than 59, 54, 49, 44, 39, 34, 30, 29, 28,27, 26, 25, 24, 23, 22, 21, or 20 pounds per thousand gallons of theliquid phase. In some embodiments, the polymers can be present in anamount of about 20 pounds per thousand gallons. Hydroxypropyl guar,carboxymethyl hydroxypropyl guar, carboxymethyl guar, cationicfunctional guar, guar or mixtures thereof, are preferred polymers foruse herein as a gelling agent. Fluids incorporating polymer basedviscosifiers may have any suitable viscosity, preferably a viscosityvalue of about 50 mPa-s or greater at a shear rate of about 100 s⁻¹ attreatment temperature, more preferably about 75 mPa-s or greater at ashear rate of about 100 s⁻¹, and even more preferably about 100 mPa-s orgreater.

In certain embodiments, the treatment fluid 106 includes an activatorpresent in an amount between about 0.1% and 50% by weight of the scaleinhibitor. In certain further embodiments, the activator reacts with afraction of the scale inhibitor to form a gel precipitate in thefracture 110 and/or subterranean formation 104. The gel precipitateslowly dissolves in produced fluids from the subterranean formation 104,releasing scale inhibitor into the produced fluid. In certainembodiments, the activator includes a divalent ion, an ionic salt,and/or calcium chloride. In certain embodiments, the scale inhibitorincludes a chemical that adsorbs to the matrix of the subterraneanformation 104, with or without the addition of an activator.

In certain embodiments, the scale inhibitor includes a compound thatinhibits the formation of carbonate and/or phosphate scales. In certainembodiments, the scale inhibitor includes a compound includingsulfonates, phosphate esters, phosphonates, phosphonate polymers,polyacrylates and polymethacrylates, polycarboxylates, and phosphorouscontaining polycarboxylates, and/or phosphonic acid derivatives. Incertain embodiments, the scale inhibitor includes a compound includingphospino-polylacrylates and/or phosphonic acid ethylene diaminederivatives. In certain embodiments, the scale inhibitor includes acompound including phosphonic acid[1,2-ethanediylbis[nitrilobis(methylene)]]tetrakis, calcium salts thereof, and/or sodiumsalts thereof. In certain embodiments, the scale inhibitor includes acompound represented by at least one of the following structures:

FIG. 2A is a schematic illustration of a particle 200. The particle 200is a porous proppant particle including scale inhibitor 202 adsorbed tointernal surfaces of the proppant matrix 204. An embodiment such as thatillustrated in FIG. 2A allows high concentrations of scale inhibitor 202to be embedded in the subterranean formation 104 and/or fracture 110with a configurable dissolution rate to allow the scale inhibitor 202release to occur over extended periods. Examples of some of thecontrollable parameters to configure the concentration and dissolutionrate of the scale inhibitor 202 include the selection of proppantmaterials, scale inhibitor 202 compositions, proppant porositypercentage and pore size.

FIG. 2B is a schematic illustration of a particle 206. The particle 206is a porous proppant particle including scale inhibitor 202 filling thebulk porosity of the proppant. An embodiment such as that illustrated inFIG. 2A allows high concentrations of scale inhibitor 202 to be embeddedin the subterranean formation 104 and/or fracture 110 with aconfigurable dissolution rate to allow the scale inhibitor 202 releaseto occur over extended periods. Examples of some of the controllableparameters to configure the concentration and dissolution rate of thescale inhibitor 202 include the selection of proppant materials, scaleinhibitor 202 compositions, proppant porosity percentage and pore size.In certain embodiments, the scale inhibitor 202 may fill the bulkporosity and be adsorbed on the proppant matrix 204.

FIG. 3 is a schematic illustration of a coated particle 300. FIG. 3illustrates the coated particle 300 as a coated proppant particle, butthe coated particle 300 in certain embodiments includes a coatedgranular scale inhibitor. In certain embodiments, the granulated scaleinhibitor and/or proppant including scale inhibitor includes a coating302 that degrades at a set of downhole conditions. The downholeconditions may be the conditions that are expected to exist in thesubterranean formation 104 during a treatment placing the particle 300,conditions expected to exist after a treatment is completed, orconditions that are expected to exist at some future operating conditionof wellbore 102.

For example, the shut-in temperature of the subterranean formation maybe above 150° C., and the coating 302 may be a substance that degradesat temperatures above 150° C. In another example, the coating 302 may bea substance that degrades in the presence of hydrocarbons, and thecoating 302 degrades over time as the wellbore 102 begins to producehydrocarbons from the subterranean formation 104. In another example,the coating 302 may be a substance that degrades in the presence of aspecific chemical, and the chemical is injected at a later time, oralternatively is released from other particles included with thetreatment fluid 106 such that the coating 302 degrades at a laterplanned or determined time. In another example, the coating 302 may be asubstance that degrades above a specific temperature, and a fluid at anelevated temperature is injected at a later time to degrade the coating302.

FIG. 4 is an illustration of a fluid breaker profile 400. The fluidbreaker profile 400 is presented as a plot of fluid viscosity 402 versustime 404. FIG. 4 represents qualitative example data illustrating anexample of the effect of scale inhibitors 202 on treatment fluid 106rheology. In certain embodiments, the scale inhibitor 202 affects thedesigned breaker treatment for the treatment fluid 106, resulting in ascale inhibitor breaker profile 406 that has higher viscosities than anominal breaker profile 408. In the example, a final fluid viscosity hasan offset value 410, indicating that the final achieved fluid viscositymay never reach the designed nominal viscosity. Utilizing routinerheology tests and measurement, a breaking procedure can be designedthat achieves the desired breaking profile for a given embodiment. Forexample, an operator can add breaker aids, reduce viscosifier loadings,or increase the amount of breaker to mitigate the difference between thescale inhibitor breaker profile 406 and the nominal breaker profile 408.In certain embodiments, the scale inhibitor 202 may enhance breakeractivity, resulting in a scale inhibitor breaker profile 406 having alower viscosity than the nominal breaker profile 408, which can also bemitigated by an operator.

FIG. 5 is an illustration 500 of a scale inhibitor concentration 502versus production fluid flowback 504 as measured by pore volumes. Theillustration 500 is example data for a system 100 including scaleinhibitor 202 in an amount at 5% by weight of the proppant. Theillustration 500 shows scale inhibitor concentration 508 degrading asfluid flows from the subterranean formation 104. The data shown in FIG.5 is example data only, but systems have been demonstrated that maintaindesign concentrations 506 of scale inhibitor 202 for more than 500 porevolumes of flowback. In certain embodiments, the scale inhibitor 202includes an initial amount and a dissolution rate characteristic suchthat the scale inhibitor concentration 508 in the produced formationfluid is greater than about 5 ppm for at least 500 fracture pore volumesof the produced fluid. In certain embodiments, the inhibitor 202includes an initial amount and a dissolution rate characteristic suchthat the scale inhibitor concentration 508 in the produced formationfluid is greater than about 10 ppm for at least 450 fracture porevolumes of the produced fluid.

The schematic flow diagram and related description which followsprovides an illustrative embodiment of performing operations forcombined fracturing treatment and scale inhibition. Operationsillustrated are understood to be exemplary only, and operations may becombined or divided, and added or removed, as well as re-ordered inwhole or part, unless stated explicitly to the contrary herein.

FIG. 6 is a schematic flow diagram of a procedure 600 for scaleinhibition. The procedure 600 includes an operation 602 to select adegradable material for coating particles according to as set ofdownhole conditions. The procedure 600 further includes an operation 604to coat an amount of particles with the degradable material, where theamount of particles include a defined volume with a scale inhibitor inthe defined volume. The procedure 600 further includes an operation 606to prepare a treatment fluid including a carrier fluid and an amount ofparticles, an operation 608 to fracture a subterranean formation, and anoperation 610 to place the treatment fluid in the fracture. Theprocedure 600 further includes an operation 612 to allow the fracture toclose on the particles. The procedure 600 further includes an operation614 to degrade the degradable material, and an operation 616 to flowproduction fluid from the formation fluid. The procedure 600 furtherincludes an operation 618 to adsorb at least a portion of the degradablematerial on the subterranean formation matrix, and an operation 620 togenerate a gel precipitate in the subterranean formation.

As is evident from the figures and text presented above, a variety ofembodiments according to the present invention are contemplated.

In one exemplary embodiment, a treatment fluid for a subterraneanformation is disclosed. The treatment fluid includes a carrier fluid anda first amount of particles including a granular scale inhibitor. Incertain embodiments, the granular scale inhibitor includes a compoundthat inhibits the formation of at least one of carbonate and phosphatescales. In certain further embodiments, the carrier fluid is ahydratable gel-based fluid, a cross-linked hydratable gel-based fluid,an oil-based fluid, a visco-elastic surfactant (VES) fluid, and/or anacid-based fluid. In certain embodiments, the carrier fluid comprises afluid with high salt tolerance.

In certain embodiments, the treatment fluid includes a second amount ofparticles including a proppant, and the first amount of particles arepresent in an amount comprising between about 1% and 5% by weight of atotal amount of particles. In certain embodiments, the treatment fluidfurther includes an activator present in an amount between about 0.1%and 50% by weight of the scale inhibitor. The activator may be adivalent ion, an ionic salt, and/or calcium chloride.

In certain embodiments, the granular scale inhibitor includes a chemicalstructured to at least partially adsorb to a formation matrix. Incertain embodiments, the granular scale inhibitor includes compoundclasses of sulfonates, phosphate esters, phosphonates, phosphonatepolymers, polyacrylates and polymethacrylates, polycarboxylates, andphosphorous containing polycarboxylates, and/or phosphonic acidderivatives. In certain embodiments, the granular scale inhibitorincludes compound classes of phospino-polylacrylates and/or phosphonicacid ethylene diamine derivatives. In certain embodiments, the granularscale inhibitor includes compound classes of phosphonicacid[1,2-ethanediylbis[nitrilobis(methylene)]]tetrakis, calcium saltsthereof, and/or sodium salts thereof.

In certain embodiments, the granular scale inhibitor further includes acoating structured to degrade at a set of downhole conditions. Incertain further embodiments, the coating includes an encapsulationmaterial, a surface coating, and/or a thin material film. In certainfurther embodiments, the coating includes polycaprolate, calciumstearate, a material structured to degrade in contact with ahydrocarbon, a material structured to degrade at a downhole temperature,and/or a material structured to degrade in a formation brine.

In an exemplary embodiment, a treatment fluid includes a carrier fluidand a first amount of particles including a proppant. The proppantincludes a porosity at least partially filled with a scale inhibitor. Incertain embodiments, the proppant includes a porous ceramic proppant. Incertain embodiments, the porosity is at least partially filled with ascale inhibitor that includes a scale inhibitor adsorbed on poresurfaces in the proppant and/or a scale inhibitor filling at least aportion of bulk porosity in the proppant. In certain embodiments, thecarrier fluid includes a hydratable gel-based fluid, a cross-linkedhydratable gel-based fluid, an oil-based fluid, a visco-elasticsurfactant (VES) fluid, and/or an acid-based fluid.

In certain embodiments, the scale inhibitor includes between about 1%and 5% of a total proppant weight. In certain embodiments, the treatmentfluid further includes an activator present in an amount between about0.1% and 50% by weight of the scale inhibitor. In certain furtherembodiments, the activator includes a divalent ion, an ionic salt,and/or calcium chloride. In certain embodiments, the scale inhibitorincludes a chemical structured to at least partially adsorb to aformation matrix.

In certain embodiments, the scale inhibitor further includes a coatingthat degrades at a set of downhole conditions. In certain embodiments,the coating includes an encapsulation material, a surface coating,and/or a thin material film. In certain embodiments, the coatingincludes polycaprolate, calcium stearate, a material structured todegrade in contact with a hydrocarbon, a material structured to degradeat a downhole temperature, and/or a material structured to degrade in aformation brine. In certain embodiments, the carrier fluid includes afluid with high salt tolerance.

In an exemplary embodiment, a method includes preparing a treatmentfluid including a carrier fluid, an amount of particles each particledefining a volume, where at least a portion of the defined volume ofeach particle comprises a scale inhibitor. In certain embodiments, themethod further includes fracturing a subterranean formation, placing thetreatment fluid in the fracture, and allowing the fracture to close onthe amount of particles.

In certain embodiments, the scale inhibitor includes an initial amountand a dissolution rate characteristic, and the method further includesproducing a formation fluid from the subterranean formation, wherein theinitial amount and dissolution rate characteristic have values such thata concentration of the scale inhibitor in the produced formation fluidis greater than about 5 ppm for at least 500 fracture pore volumes ofthe produced formation fluid. In certain embodiments, the initial amountand dissolution rate characteristic have values such that aconcentration of the scale inhibitor in the produced formation fluid isgreater than about 10 ppm for at least 450 fracture pore volumes of theproduced formation fluid.

In certain embodiments, the scale inhibitor includes a compound thatinhibits the formation of at least one of carbonate and phosphatescales. In certain further embodiments, the amount of particles includesat least one of: a proppant impregnated with the scale inhibitor, aproppant having bulk porosity at least partially filled with the scaleinhibitor, and a granular particle comprising the scale inhibitor. Incertain further embodiments, the method further includes flowingproduction fluid from the subterranean formation into a wellboreintersecting the subterranean formation, and adsorbing at least aportion of the scale inhibitor on a matrix of the subterraneanformation.

In certain embodiments, the method includes coating the amount ofparticles with a degradable material, and degrading the degradablematerial after the placing the treatment fluid. In certain embodiments,degrading the degradable material includes selecting a degradablematerial that degrades at a set of downhole conditions present in thesubterranean formation. In certain embodiments, degrading the degradablematerial includes injecting a composition that reacts with thedegradable material. In certain embodiments, degrading the degradablematerial includes injecting a fluid at an elevated temperature. Incertain embodiments, the coating includes an encapsulation material, asurface coating, and/or a thin material film. In certain embodiments,the treatment fluid includes an activator present in an amount betweenabout 0.1% and 50% by weight of the scale inhibitor. In certainembodiments, the method further includes generating a gel precipitate inthe subterranean formation, where the gel precipitate includes at leasta fraction of the scale inhibitor reacted with the activator.

In one exemplary embodiment, a system includes a wellbore intersecting asubterranean formation and an amount of treatment fluid, the treatmentfluid including a carrier fluid, an amount of particles each particledefining a volume, where at least a portion of the defined volume ofeach particle comprises a scale inhibitor. The system further includes apump that fractures the subterranean formation and places the treatmentfluid in the fracture. In certain embodiments, the amount of particlesincludes an amount of a porous ceramic proppant impregnated with thescale inhibitor. In certain further embodiments, the carrier fluidincludes a hydratable gel-based fluid, a cross-linked hydratablegel-based fluid, an oil-based fluid, a visco-elastic surfactant (VES)fluid, and/or an acid-based fluid.

While the invention has been illustrated and described in detail in thedrawings and foregoing description, the same is to be considered asillustrative and not restrictive in character, it being understood thatonly the preferred embodiments have been shown and described and thatall changes and modifications that come within the spirit of theinventions are desired to be protected. It should be understood thatwhile the use of words such as preferable, preferably, preferred, morepreferred or exemplary utilized in the description above indicate thatthe feature so described may be more desirable or characteristic,nonetheless may not be necessary and embodiments lacking the same may becontemplated as within the scope of the invention, the scope beingdefined by the claims that follow. In reading the claims, it is intendedthat when words such as “a,” “an,” “at least one,” or “at least oneportion” are used there is no intention to limit the claim to only oneitem unless specifically stated to the contrary in the claim. When thelanguage “at least a portion” and/or “a portion” is used the item caninclude a portion and/or the entire item unless specifically stated tothe contrary.

1. A treatment fluid for a subterranean formation, the treatment fluidcomprising: a carrier fluid; a first amount of particles comprising agranular scale inhibitor; and wherein the granular scale inhibitorcomprises a compound that inhibits the formation of at least one ofcarbonate and phosphate scales.
 2. The treatment fluid of claim 1,wherein the granular scale inhibitor comprises a particle size greaterthan about 25 microns.
 3. The treatment fluid of claim 1, wherein thecarrier fluid comprises at least one fluid selected from the fluidsconsisting of: a hydratable gel-based fluid, a cross-linked hydratablegel-based fluid, an oil-based fluid, a visco-elastic surfactant (VES)fluid, and an acid-based fluid.
 4. The treatment fluid of claim 1,further comprising a second amount of particles comprising a proppant,wherein the first amount of particles are present in an amountcomprising between about 1% and 5% by weight of a total amount ofparticles.
 5. The treatment fluid of claim 1, further comprising anactivator present in an amount between about 0.1% and 50% by weight ofthe scale inhibitor.
 6. The treatment fluid of claim 5, wherein theactivator comprises at least one activator selected from the listconsisting of a divalent ion, an ionic salt, and calcium chloride. 7.The treatment fluid of claim 1, wherein the carrier fluid comprises afluid with high salt tolerance.
 8. The treatment fluid of claim 1,wherein the granular scale inhibitor comprises a chemical structured toat least partially adsorb to a formation matrix.
 9. The treatment fluidof claim 1, wherein the granular scale inhibitor comprises at least onecompound selected from the classes consisting of sulfonates, phosphateesters, phosphonates, phosphonate polymers, polyacrylates andpolymethacrylates, polycarboxylates, and phosphorous containingpolycarboxylates, and phosphonic acid derivatives.
 10. The treatmentfluid of claim 1, wherein the granular scale inhibitor comprises atleast one compound selected from the classes consisting ofphospino-polylacrylates and phosphonic acid ethylene diaminederivatives.
 11. The treatment fluid of claim 1, wherein the granularscale inhibitor comprises at least one compound selected from theclasses consisting of phosphonicacid[1,2-ethanediylbis[nitrilobis(methylene)]]tetrakis, calcium saltsthereof, and sodium salts thereof.
 12. The treatment fluid of claim 1,wherein the granular scale inhibitor further includes a coatingstructured to degrade at a set of downhole conditions.
 13. The treatmentfluid of claim 12, wherein the coating comprises a coating selected fromthe group consisting of an encapsulation material, a surface coating,and a thin material film.
 14. The treatment fluid of claim 12, whereinthe coating comprises at least one coating selected from the groupconsisting of polycaprolate, calcium stearate, a material structured todegrade in contact with a hydrocarbon, a material structured to degradeat a downhole temperature, and a material structured to degrade in aformation brine.
 15. A treatment fluid for a subterranean formation, thetreatment fluid comprising: a carrier fluid; a first amount of particlescomprising a proppant; and wherein the proppant includes a porosity atleast partially filled with a scale inhibitor.
 16. The treatment fluidof claim 15, wherein the proppant has a size at least equal to a 100mesh.
 17. The treatment fluid of claim 15, wherein the proppantcomprises a porous ceramic proppant.
 18. The treatment fluid of claim15, wherein the porosity at least partially filled with a scaleinhibitor comprises at least one of the scale inhibitor adsorbed on poresurfaces in the proppant and the scale inhibitor filling at least aportion of bulk porosity in the proppant.
 19. The treatment fluid ofclaim 15, wherein the carrier fluid comprises at least one fluidselected from the fluids consisting of: a hydratable gel-based fluid, across-linked hydratable gel-based fluid, an oil-based fluid, avisco-elastic surfactant (VES) fluid, and an acid-based fluid.
 20. Thetreatment fluid of claim 15, wherein the scale inhibitor comprisesbetween about 1% and 5% of a total proppant weight.
 21. The treatmentfluid of claim 15, further comprising an activator present in an amountbetween about 0.1% and 50% by weight of the scale inhibitor.
 22. Thetreatment fluid of claim 21, wherein the activator comprises at leastone activator selected from the list consisting of a divalent ion, anionic salt, and calcium chloride.
 23. The treatment fluid of claim 15,wherein the scale inhibitor comprises a chemical structured to at leastpartially adsorb to a formation matrix.
 24. The treatment fluid of claim15, wherein the scale inhibitor comprises at least one compound selectedfrom the classes consisting of sulfonates, phosphate esters,phosphonates, phosphonate polymers, polyacrylates and polymethacrylates,polycarboxylates, and phosphorous containing polycarboxylates, andphosphonic acid derivatives.
 25. The treatment fluid of claim 15,wherein the scale inhibitor comprises at least one compound selectedfrom the classes consisting of phospino-polylacrylates and phosphonicacid ethylene diamine derivatives.
 26. The treatment fluid of claim 15,wherein the scale inhibitor comprises at least one compound selectedfrom the classes consisting of phosphonicacid[1,2-ethanediylbis[nitrilobis(methylene)]]tetrakis, and calcium andsodium salts thereof.
 27. The treatment fluid of claim 15, wherein thescale inhibitor further includes a coating structured to degrade at aset of downhole conditions.
 28. The treatment fluid of claim 27, whereinthe coating comprises a coating selected from the group consisting of anencapsulation material, a surface coating, and a thin material film. 29.The treatment fluid of claim 27, wherein the coating comprises at leastone coating selected from the group consisting of polycaprolate, calciumstearate, a material structured to degrade in contact with ahydrocarbon, a material structured to degrade at a downhole temperature,and a material structured to degrade in a formation brine.
 30. Thetreatment fluid of claim 15, wherein the carrier fluid comprises a fluidwith high salt tolerance.
 31. A method, comprising: preparing atreatment fluid comprising a carrier fluid, an amount of particles eachparticle defining a volume, wherein at least a portion of the definedvolume of each particle comprises a scale inhibitor, and wherein theamount of particles comprise a particle size greater than about 25microns; fracturing a subterranean formation; placing the treatmentfluid in the fracture; and allowing the fracture to close on the amountof particles.
 32. The method of claim 31, wherein the scale inhibitorcomprises an initial amount and a dissolution rate characteristic, themethod further comprising producing a formation fluid from thesubterranean formation, wherein the initial amount and dissolution ratecharacteristic have values such that a concentration of the scaleinhibitor in the produced formation fluid is greater than about 5 ppmfor at least 500 fracture pore volumes of the produced formation fluid.33. The method of claim 31, wherein the scale inhibitor comprises aninitial amount and a dissolution rate characteristic, the method furthercomprising producing a formation fluid from the subterranean formation,wherein the initial amount and dissolution rate characteristic havevalues such that a concentration of the scale inhibitor in the producedformation fluid is greater than about 10 ppm for at least 450 fracturepore volumes of the produced formation fluid.
 34. The method of claim31, wherein the scale inhibitor comprises a compound that inhibits theformation of at least one of carbonate and phosphate scales.
 35. Themethod of claim 31, wherein the amount of particles comprises at leastone particle selected from the list consisting of: a proppantimpregnated with the scale inhibitor, a proppant having bulk porosity atleast partially filled with the scale inhibitor, and a granular particlecomprising the scale inhibitor.
 36. The method of claim 31, furthercomprising flowing production fluid from the subterranean formation intoa wellbore intersecting the subterranean formation, and adsorbing atleast a portion of the scale inhibitor on a matrix of the subterraneanformation.
 37. The method of claim 31, further comprising coating theamount of particles with a degradable material, and degrading thedegradable material after the placing the treatment fluid.
 38. Themethod of claim 37, wherein the degrading the degradable materialcomprises selecting a degradable material structured to degrade at a setof downhole conditions present in the subterranean formation.
 39. Themethod of claim 37, wherein the degrading the degradable materialcomprises injecting a composition that reacts with the degradablematerial.
 40. The method of claim 37, wherein the degrading thedegradable material comprises injecting a fluid at an elevatedtemperature.
 41. The method of claim 37, wherein the coating comprises acoating selected from the group consisting of an encapsulation material,a surface coating, and a thin material film.
 42. The method of claim 31,wherein the treatment fluid further includes an activator present in anamount between about 0.1% and 50% by weight of the scale inhibitor. 43.The method of claim 42, further comprising generating a gel precipitatein the subterranean formation, wherein the gel precipitate comprises atleast a fraction of the scale inhibitor reacted with the activator. 44.A system, comprising: a wellbore intersecting a subterranean formation;an amount of treatment fluid, comprising: a carrier fluid, an amount ofparticles each particle defining a volume, wherein at least a portion ofthe defined volume of each particle comprises a scale inhibitor; and apump structured to fracture the subterranean formation, and to place thetreatment fluid in the fracture.
 45. The system of claim 44, wherein theamount of particles comprises an amount of a porous ceramic proppantimpregnated with the scale inhibitor.
 46. The system of claim 45,wherein the amount of particles comprise a particle size at least equalto a 100 mesh.
 47. The system of claim 44, wherein the carrier fluidcomprises at least one fluid selected from the fluids consisting of: ahydratable gel-based fluid, a cross-linked hydratable gel-based fluid,an oil-based fluid, a visco-elastic surfactant (VES) fluid, and anacid-based fluid.
 48. The system of claim 44, wherein the amount ofparticles comprise a particle size greater than about 25 microns.